In the recovery of hydrocarbons from subterranean formations, particularly in such formations wherein the wellbore also traverses water-bearing zones, the desire is to facilitate the movement of hydrocarbons to the wellbore so that the hydrocarbons may be pumped from the well. At the same time, there is a corresponding desire to limit the movement of formation water into the wellbore and production thereof. In order to enhance the effectiveness of some of these methods for increasing (or stimulating) hydrocarbon production, the proper placement of stimulation fluids, for example, acidizing and/or fracturing fluids, at the hydrocarbon zones and minimizing the loss thereof into the water zones is desirable.
Acidizing is used to stimulate hydrocarbon production from a well. There are two types of acidizing treatments: (1) matrix acidizing and (2) fracture acidizing with the difference between them relating to injection rates and pressures. Fracture acidizing is acidizing at injection rates above fracture pressure. Fracture acidizing is used for creating cracks or fractures in the formation to increase the available flow area and thereby increase well productivity. Acidizing at injection rates below fracture pressure is termed matrix acidizing. Matrix acidizing is primarily used for damage removal and to restore the permeability to original reservoir permeability or higher. The damage is primarily skin damage caused by drilling, completion and workover fluids and precipitation of deposits from produced water or oil (such as scale). Removal of severe plugging in carbonate and sandstone formations can result in very large increases in well productivity. Oil well flow behavior is greatly affected by the geometry of radial flow into the wellbore. The pressure gradient, for example, psi per foot, is proportional to the flow velocity and is very small at large distances from the wellbore. At points close to the wellbore, the flow area is much smaller and the flowing pressure gradient is much higher. Because of this small flow area, any damage to the formation close to the wellbore, say within 20 feet thereof and sometimes within as little as 3 feet therefrom, may be the cause most of the total pressure draw down during production and thereby dominate well performance.
Since the acidizing fluids do not discriminate between hydrocarbon and water bearing zones, an undesired result may be obtained wherein the production of formation water is increased. Thus, there is a need to direct acidizing fluids away from water bearing zones and preferably also limit the amount of formation water produced once the well is "turn around."
Further, at the end of a conventional hydraulic fracturing operation, it is necessary to bring back to the surface as much as possible of the hydraulic fluid components such as polymer, typically a galactomannan polysaccharide, broken polymer components, salts, typically ammonium chloride, potassium chloride and tetramethyl ammonium chloride, and fluid, typically a brine, pumped into the formation during treatment. This process of bringing the fluid back to the surface after the treatment is termed "turning the well around". This process lasts from the moment fluid is begun to be brought back until the gas or oil is produced in sufficient quantities for sale. The well turn around process can last from hours to several days. During this period, it has historically been possible to recover approximately one third of the polymer and fluid pumped during the hydraulic fracturing treatment.
In the case of low permeability (less than about 1 md) dry gas reservoirs (that is, gas reservoirs which produce hydrocarbons and little or no formation water), it is possible to dramatically improve the recovery of polymer and fluid during the well turnaround period by increasing the rate at which the fluids are brought back to the surface. This has been documented in two published field studies. SPE 31094 (D. Pope, L. Britt, V. Constien, A. Anderson, L. Leung, "Field Study of Guar Removal from Hydraulic Fractures: presented at the SPE International Symposium on Formation Damage Control, Lafayette, La., Feb. 14-15, 1995) provided the first demonstration that increased flowback rate results in increased polymer recovery which results in increased well productivity. This was taken further in SPE 36468 (A. J. Anderson, P. J. N. Ashton, J. Lang and M. L. Samuelson, "Production Enhancement Through Aggressive Flowback Procedures in the Codell Formation" presented at the SPE Annual Technical Conference and Exhibition, Denver, Co., Oct. 6-9, 1997) where polymer recovery was increased to more than 60% of the amount pumped during the treatment and 90 day cumulative production was increased by more than 50% over those of offset wells with less aggressive flowback rates. Similar results have been observed in other low permeability dry gas wells. (See, for example, SPE 30495, P. R. Howard, M. T. King, M. Morris, J. P. Feraud, G. Slusher, S. Lipari, "Fiber/Proppant Mixtures Control Proppant Flowback in South Texas" presented at the SPE Annual Technical Conference and Exhibition, Dallas, Tex., Oct. 22-25, 1995.)
The flowback pattern from this type of formation is very distinctive. This is illustrated in FIG. 1. This figure presents a graph of the concentration of the polymer, in this case guar, in samples of fluid flowed back to the surface after the hydraulic fracturing treatment of a dry gas well as a function of the time between the start of the flowback and when the sample was collected. The concentration of polymer in these samples is equal to or greater than the concentration of guar pumped during the treatment and is relatively constant over time. This behavior continues for months after the turn around period is over and the well is in production.
However, in recent studies relating to oil wells, we have discovered and demonstrated that the inflow of formation water during the well turn around period is detrimental to the ability to maximize the polymer recovered after a hydraulic fracturing treatment of a gas or oil well and to efforts to maximize well productivity. As a result, we have identified that there is a need to control the inflow of this formation water during the well turn around stage in order to be able to maximize well productivity.